Fields in Production

12 Fields in production

Southern North Sea sector Ekofisk area (Ekofisk, Eldfisk, Embla and Tor) ...... 71 Glitne ...... 74 Gungne ...... 75 Gyda (incl Gyda South) ...... 76 Hod ...... 77 Sigyn ...... 78 Sleipner West ...... 79 Sleipner East ...... 80 Tambar ...... 81 Ula ...... 82 Valhall ( incl Valhall flanks and Valhall water injection) ...... 83 Varg ...... 84

Northern North Sea sector Balder (incl Ringhorne) ...... 86 Brage ...... 87 Frigg ...... 88 Gullfaks (incl Gullfaks Vest) ...... 90 Gullfaks South (incl Rimfaks and Gullveig) ...... 92 Heimdal ...... 94 Huldra ...... 95 Jotun ...... 96 Murchison ...... 97 Oseberg (Oseberg, Oseberg West, Oseberg East, Oseberg South) ...... 98 Snorre (incl Snorre B) ...... 101 Statfjord ...... 103 Statfjord North ...... 105 Statfjord East ...... 106 Sygna ...... 107 Tordis (incl Tordis East and Borg) ...... 108 Troll phase I ...... 110 Troll phase II ...... 112 Tune ...... 114 Vale ...... 115 Veslefrikk ...... 116 Vigdis ...... 117 Visund ...... 118

Norwegian Sea Draugen ...... 120 Heidrun ...... 121 Njord ...... 122 Norne ...... 123 Åsgard ...... 124

Fields which have ceased production ...... 126 12

Explanation of the tables in chapters 12–14

Interests in fields do not necessarily correspond with interests in the individual production licences (unitised fields or ones for which the sliding scale has been exercised have a different composition of interests than the production licence). Because interests are shown up to two decimal places, licensee holdings in a field may add up to less than 100 per cent. Interests are shown at 1 January 2003.

Recoverable reserves originally present refers to reserves in resource categories 0, 1, 2 and 3 in the NPD’s classification system (see the definitions below).

Recoverable reserves remaining refers to reserves in resource categories 1, 2 and 3 in the NPD’s classification system (see the definitions below).

Resource category 0: Petroleum sold and delivered Resource category 1: Reserves in production Resource category 2: Reserves with an approved plan for development and operation Resource category 3: Reserves which the licensees have decided to develop

Explanation of the figures

Oil: 1 000 b/d Gas: bn scm/year NGL: mill tonnes/year Condensate: mill scm/year

FIELDS IN PRODUCTION 69 2˚ 4˚ 6˚

169 59˚ 59˚ 204 189 25 242 STAVANGERSTAVANGER 15/3-1 S Gudrun Statpipe eepipe II A eepipe 15/3-4 Z Z 25 265 265 Glitne 48 29 15/5-2 ipe II B 243

48 eep 15/5-1 Dagny Z 29 15/919 S Volve Sleipner 16/7-2 12 West 46 46 Sleipner East 15/8-1 72 Alpha Gungne 241 Sigyn 38

38 Varg 15/12-12 18/10-1 58˚

58˚ Eu

opip r opipe II

e I Yme 271

7/7-2 148

240 Mime 18 Ula 019 Cod 57˚ 57˚ Tambar 1/3-6 1/2-1 143 Gyda 19 2/2-5 19 274 239 18 2/4-17 Tjalve 2/4-10 239 146 Tor Albuskjell 1/5-2 Flyndre West Ekofisk Ekofisk 2/5-3 South-East Tor 18 66 44 Edda Eldfisk Tommeliten Gamma 3/7-4 Trym 147 2/7-19 Embla 2/7-29 6 18 Valhall 273 Awarded acreage Fra 2/12-1 Freja Hod npipe 113 Norpip Norpipe

e 56˚ 56˚

2˚ 4˚

Southern North Sea sector

The southern part of Norway’s North Sea sector became important for the country at an early stage, with Ekofisk as the first Norwegian offshore field to come on stream more than 30 years ago. Ekofisk serves as a hub for petroleum operations in this area, with surrounding developments utilising the infrastructure which ties it to continental Europe and Britain. Norwegian oil and gas is exported from Ekofisk to Teesside in the UK and Emden in Germany respectively. Although production from this part of the NCS has lasted for many years, remaining resources in the region are substantial. Oil and gas output is accordingly expected to continue beyond another three decades.

70 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

500 16 14 400 12 300 10 8 200 6 100 4 2 0 0 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 12

Ekofisk area (incl Ekofisk, Eldfisk, Embla and Tor)

Ekofisk, Eldfisk and Embla

Blocks and Blocks 2/4 and 2/7 - production licence 018. production licences Both blocks awarded in 1965.

Progress On stream in 1971

Operator TotalFinaElf Exploration Norge AS 39.90% Licensees ConocoPhillips Norge 35.11% (rounded off to Norsk Agip AS 12.39% two decimal places) Norsk Hydro Produksjon a.s 6.65% Petoro AS1 5.00% Statoil ASA 0.95%

Recoverable reserves Originally present: Remaining at 31.12.02: 574.1 mill scm oil 182.7 mill scm oil 225.4 bn scm gas 68.7 bn scm gas 17.8 mill tonnes NGL 3.6 mill tonnes NGL

Production Estimated production in 2003: Oil: 354 000 b/d Gas: 5.7 bn scm NGL: 0.4 mill tonnes

Transport Oil is piped through the Norpipe system to Teesside in the UK, while gas is piped to Emden in Germany.

Investment Total investment is likely to be NOK 175 bn (2003 value). NOK 148 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Phillipsbasen, Tananger

1 Petoro AS serves as the licensee for the SDFI.

FIELDS IN PRODUCTION 71 12

Ekofisk area (incl Ekofisk, Eldfisk, Embla and Tor) cont

Tor

Blocks and Block 2/4 - production licence 018. Awarded in 1965. production licences Block 2/5 - production licence 006. Awarded in 1965.

Progress Government approval: 1973 On stream in 1978

Operator ConocoPhillips Norge

Licensees TotalFinaElf Exploration Norge AS 48.20 % (rounded off to ConocoPhillips Norge 30.66 % two decimal places) Norsk Agip AS 10.82 % Norsk Hydro Produksjon a.s 5.81 % Petoro AS1 3.69 % Statoil ASA 0.83 %

Recoverable reserves Originally present: Remaining at 31.12.02: 26.0 mill scm oil 4.4 mill scm oil 11.5 bn scm gas 0.9 bn scm gas 1.2 mill tonnes NGL 0.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 4 300 b/d Gas: 0.05 bn scm NGL: 0.005 mill tonnes

Transport Oil is piped through the Norpipe system to Teesside in the UK, while gas is piped to Emden in Germany.

Investment Total investment is likely to be NOK 8.8 bn (2003 value). NOK 8.4 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Phillipsbasen, Tananger

1 Petoro AS serves as the licensee for the SDFI.

72 FIELDS IN PRODUCTION 12

The Ekofisk area comprises the Ekofisk, Eldfisk, Embla and Tor fields, which lie in 70-75 metres of water. In addition come Albuskjell, Cod, Edda and West Ekofisk, which have ceased production.

This area has been developed in five phases. Ekofisk and its central processing facilities were developed in two stages, with production starting in 1971. Cod and West Ekofisk represented phase three. Oil was initial- ly loaded into tankers on the fields, but has been piped since 1975 through the Norpipe line to Teesside in the UK. Pipeline transport of gas through Norpipe to Emden in Germany began in 1977.

Approved by the authorities in 1975, the fourth development phase covered Albuskjell, Eldfisk and Edda. The last of these came on stream in 1979. The fifth phase was prompted by a desire to improve recovery from Ekofisk, and the 2/4-K water injection platform began operation in December 1987. Expanded several times, water injection capacity on the field is currently just under one mill b/d.

The Edda platform was modified in 1988 to receive gas from the Tommeliten field. A decision to develop the Embla field south of Ekofisk was taken in 1990, with production starting in 1993.

A new plan for development and operation of the Ekofisk field (Ekofisk II) received approval in 1994, when the licence for the Ekofisk area was extended to 2028. A new Ekofisk field centre comprising two platforms has been installed on the field. The 2/4-X wellhead platform was put in place during the autumn of 1996, fol- lowed by the 2/4-J processing and transport installation in August 1997. Ekofisk II came on stream in August 1998, and is expected to produce for the next 30 years.

The Ekofisk, Eldfisk, Embla and Tor fields are tied back to the new field centre, and will thereby remain on stream. Ordinary production from Cod, Edda, Albuskjell and West Ekofisk has ceased.

A total of 29 platforms are installed in the Ekofisk area. In connection with the development of the new field centre, many of these installations have already been shut in. On the basis of the cessation plan for Ekofisk I submitted to the authorities in the autumn of 1999, it was resolved in December 2001 to remove 14 steel structures and the topside on the concrete Ekofisk tank to land for recycling of their materials. The bulk of this removal work is due to be completed by 2013.

The plan for development and operation of Eldfisk water injection was approved in 1997. It involves a new platform, 2/7-E, with equipment for water injection, gas lift and gas injection on the Eldfisk field, tied back to one of the existing installations by a bridge. The development was completed in 2000.

Declining pressure in Ekofisk has caused seabed subsidence, and operator ConocoPhillips initiated efforts in 1985 to safeguard the platforms against this effect. Six of nine steel platforms in the Ekofisk centre were therefore jacked up by six metres in 1987, and a protective concrete wall was installed around the Ekofisk tank in 1989. Seabed subsidence has slowed substantially after waterflooding stabilised the pressure. Since production started in 1971, the seabed has subsided by about seven metres. The new platforms, which came on stream in 1998, have been designed to cope with up to 20 metres of seabed subsidence.

FIELDS IN PRODUCTION 73 Oil: 1 000 b/d

40 35 30 25 20 15 10 5 0 12 2001 2002 2003

Glitne

Blocks and Block 15/5 - production licence 048B. Awarded 1977, carve-out 2001. production licences Block 15/6 - production licence 029B. Awarded 1977, carve-out 2001.

Progress Government approval: September 2000. Production start-up: 29 August 2001.

Operator Statoil ASA

Licensees Statoil ASA 58.9 % TotalFinaElf Exploration Norge AS 21.8 % Det Norske Oljeselskap AS 10.0 % Dong Norge AS 9.3 %

Recoverable reserves Originally present: Remaining at 31.12.02: 5.9 mill scm oil 3.0 mill scm oil

Production Forecast production in 2001: Oil: 26 000 b/d

Investment Total investment is likely to be NOK 1.2 mill (2003 value) NOK 0.9 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

Glitne was proven in 1995 and lies in 110 metres of water 40 km north-west of the Sleipner area. Its development solution is based on leasing the Petrojarl 1 production ship, which is tied to four production wells and a water injector. Oil from Glitne is processed and stored on the vessel before being transferred to shuttle tankers. Associated gas is used for fuel or gas lift, with surplus gas being injected back below ground.

74 FIELDS IN PRODUCTION Condensate: mill scm/year NGL: mill tonnes/year

0.6 0.25

0.5 0.2 0.4 0.15 0.3 0.1 0.2 0.1 0.05 0 0 1996 1997 1998 1999 2000 2001 2002 2003 12

Gungne

Block and Block 15/9 - production licence 046. Awarded 1976. production licence

Progress Government approval: August 1995 Production start-up: April 1996

Operator Statoil ASA

Licensees Statoil ASA 52.6% Esso Expl & Prod Norway AS 28.0% TotalFinaElf Exploration Norge AS 10.0% Norsk Hydro Produksjon a.s 9.4%

Recoverable reserves Originally present: Remaining at 31.12.02: 9.9 bn scm gas 9.9 bn scm gas 1.3 mill tonnes NGL 0.6 mill tonnes NGL 3.1 mill scm condensate 1.0 mill scm condensate

Production Estimated production in 2003: Gas: 1.17 bn scm NGL: 0.19 mill tonnes Condensate: 0.50 mill scm

Investment Total investment is likely to be NOK 1.3 bn (2003 value). NOK 1 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

Proven in 1982, Gungne is a satellite of Sleipner East and lies in 83 metres of water. It came on stream in April 1996 through a well drilled from Sleipner A. An additional well to the field was completed in 2001.

FIELDS IN PRODUCTION 75 Oil: 1 000 b/d NGL: mill tonnes/year

70 0.25 60 0.2 50 40 0.15 30 0.1 20 0.05 10 0 0 12 1990 1992 1994 1996 1998 2000 2002

Gyda (incl Gyda South)

Block and Block 2/1 - production licence 019B. Awarded 1977. production licence Block 1/3 - production licence 065. Awarded 1981.

Progress Government approval: June 1987 Production start-up: June 1990

Operator BP Norge AS

Licensees BP Norge AS 61% Dong Norge AS 34% Norske AEDC A/S 5%

Recoverable reserves Originally present: Remaining at 31.12.02: 34.0 mill scm oil 3.0 mill scm oil 5.8 bn scm gas 0.5 bn scm gas 1.8 mill tonnes NGL 0.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 15 000 b/d NGL: 0.04 mill tonnes

Investment Total investment is likely to be NOK 14.6 bn (2003 value). NOK 13.7 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Sola

The Gyda field was proven in 1980, and has been developed with an integrated steel platform in 66 metres of water. Oil is piped to a tie-in with the Ula pipeline and on via the Ekofisk Centre to Teesside, while gas goes through a dedicated pipeline to the Ekofisk Centre for sale to the Ekofisk group. Govern- ment approval to develop the small Gyda South satellite was given in 1993. This field is being drained with two extended-reach wells drilled from the Gyda platform. Gyda South came on stream in 1995.

76 FIELDS IN PRODUCTION Oil: 1 000 b/d NGL: mill tonnes/year jg 30 0.06 25 0.05 20 0.04 15 0.03 10 0.02 5 0.01 0 0

7 8 9 0 1 91 92 9 0 9 9 993 99 99 9 00 1990 1 1 1 1994 1995 1996 1 1 1 2 20 2002 2003 12

Hod

Block and Block 2/11 - production licence 033. Awarded 1969. production licence

Progress Government approval: June 1988 Production start-up: September 1990

Operator BP Norge AS

Licensees Amerada Hess Norge AS 25% BP Norge AS 25% Enterprise Oil Norge AS 25% TotalFinaElf Exploration Norge AS 25%

Recoverable reserves Originally present: Remaining at 31.12.02: 8.3 mill scm oil 1.0 mill scm oil 1.6 bn scm gas 0.3 bn scm gas 0.2 mill tonnes NGL

Production Estimated production in 2003: Oil: 7 000 b/d NGL: 0.009 mill tonnes

Investment Total investment is likely to be NOK 2.2 bn (2003 value) NOK 2.1 bn (2003 value) had been invested at 31.12.02

Operating organisation Stavanger

Main supply base Phillipsbasen/Akerbasen, Tananger

Hod has been developed with a single unstaffed wellhead platform in 72 metres of water, remotely con- trolled from the Valhall field 13 km further north. Oil and gas are separated and metered on the Hod platform, and piped as a two-phase flow for final processing on Valhall.

FIELDS IN PRODUCTION 77 12

Sigyn

Block and Block 16/7 - production licence 072. Awarded 1981. production licence

Progress Government approval: August 2001 Production start-up: December 2002

Operator Esso Expl & Prod Norway AS

Licensees Statoil ASA 50% Esso Expl & Prod Norway AS 40% Norsk Hydro Produksjon a.s 10%

Recoverable reserves Originally present: Remaining at 31.12.02: 5.1 bn scm gas 5.1 bn scm gas 1.5 mill tonnes NGL 1.5 mill tonnes NGL 3.0 mill scm condensate 3.0 mill scm condensate

Production Estimated production in 2003: Gas: 1.1 bn scm NGL: 0.4 mill tonnes Condensate: 0.9 mill scm

Investment Total investment is likely to be NOK 3.2 bn (2003 value) NOK 2.1 bn (2003 value) had been invested at 31.12.02

Operating organisation Stavanger

Main supply base Dusavik

Sigyn was proven in 1982 and lies in roughly 70 metres of water in the Sleipner area. The field is tied back to Sleipner A. After processing on that platform, Sigyn gas is exported via the Sleipner dry gas system. Its condensate travels in the existing pipeline from Sleipner to Kårstø.

78 FIELDS IN PRODUCTION Produktion, Sleipner East/West Gas: bn scm/year Condensate: mill scm/year

15 6 5 10 4 3 5 2 1 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 12

Sleipner West

Block and Block 15/6 - production licence 029. Awarded 1969. production licence Blocks 15/8, 15/9 - production licence 046. Awarded 1976.

Progress Government approval: December 1992 Production start-up: August 1996

Operator Statoil ASA

Licensees Statoil ASA 49.50% (rounded off to two Esso Expl & Prod Norway AS 32.24% decimal places) TotalFinaElf Exploration Norge AS 9.41% Norsk Hydro Produksjon a.s 8.85%

Recoverable reserves Originally present: Remaining at 31.12.021: 104.2 bn scm gas 84.9 bn scm gas 8.1 mill tonnes NGL 5.8 mill tonnes NGL 28.1 mill scm condensate 10.0 mill scm condensate

Production Estimated production in 2003: Gas: 9.84 bn scm NGL: 0.6 mill tonnes Condensate: 1.68 mill scm

Investment Total investment is likely to be NOK 24.5 bn (2003 value). NOK 19.7 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

1 Combined for Sleipner West and East.

Sleipner West was proven in 1974 and lies in 110 metres of water. It has been tied back to Sleipner East, and shares the same operations organisation. Sleipner West is produced through two installations: the Sleipner B wellhead platform and the Sleipner T gas treatment facility. Unprocessed wellstreams from Sleipner B are piped the 12 kilometres to Sleipner T, which is linked by a bridge to Sleip- ner A on the Sleipner East field. Carbon dioxide is removed from the wellstream on the T platform and injected into a sub-surface formation. The gas is piped to continental Europe while its condensate is landed at Kårstø. Plans call for precompression to start on Sleipner T in the autumn of 2004.

FIELDS IN PRODUCTION 79 Produktion, Sleipner East/West Gas: bn scm/year Condensate: mill scm/year

15 6 5 10 4 3 5 2 1 0 0 12 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Sleipner East

Block and Block 15/9 - production licence 046. Awarded 1976. production licence

Progress Government approval: December 1986 Production start-up: August 1993

Operator Statoil ASA

Licensees Statoil ASA 49.6 % Esso Expl & Prod Norway AS 30.4 % Norsk Hydro Produksjon a.s 10.0 % TotalFinaElf Exploration Norge AS 10.0 %

Recoverable reserves Originally present: Remaining at 31.12.021: 58.0 bn scm gas 84.9 bn scm gas 11.3 mill tonnes NGL 5.8 mill tonnes NGL 25.2 mill scm condensate 10.0 mill scm condensate

Production Estimated production in 2003: Gas: 1.18 bn scm NGL: 0.37 mill tonnes Condensate: 0.8 mill scm

Investment Total investment is likely to be NOK 36.1 bn (2003 value). NOK 34.6 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

1 Combined for Sleipner West and East.

Sleipner East was discovered in 1981 and lies in 82 metres of water. It has been developed with the integrated Sleipner A production, drilling and quarters platform, two templates for subsea wells, a riser platform and a flare stack. The gas is piped to continental Europe while its condensate is landed at Kårstø. The Loke satellite has been developed with a single subsea well tied back to Sleipner A. After the Ty formation had been drained in 1997, the well was extended to the Hugin/Skagerrak formation and brought back on stream in 1998. Sigyn has been developed with full wellstream transfer to Sleipner A and began production in 2002.

80 FIELDS IN PRODUCTION Oil: 1 000 b/d NGL: mill tonnes/year jg 35 0.05 30 0.04 25 20 0.03 15 0.02 10 0.01 5 0 0 2001 2002 2003 12

Tambar

Blocks and Block 1/3 - production licence 065. Awarded 1981. production licences Block 2/1 - production licence 019B. Awarded 1977.

Progress Government approval: April 2000 Production start-up: July 2001

Operator BP Norge AS

Licensees BP Norge AS 55% Dong Norge AS 45%

Recoverable reserves Originally present: Remaining at 31.12.02: 7.0 mill scm oil 4.8 mill scm oil 2.3 bn scm gas 2.3 bn scm gas 0.2 mill tonnes NGL 0.1 mill tonnes NGL

Production Forecast production in 2002: Oil: 21 500 b/d NGL: 0.03 mill tonnes

Investment Total investment is likely to be NOK 1.5 bn (2003 value). NOK 1.5 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Sola

Tambar was proven in 1982 and lies in 68 metres of water, about 16 km south-east of Ula and roughly 12 km north-west of Gyda. The field has been developed with an unstaffed wellhead platform tied back to Ula. Its production is exported to Ula for processing and onward transport by pipeline via Ekofisk to Teesside in the UK. Gas from Tambar is being injected into Ula to help improve recovery from this field.

FIELDS IN PRODUCTION 81 Oil: 1 000 b/d NGL: mill tonnes/year

140 0.3 120 0.25 100 0.2 80 0.15 60 40 0.1 20 0.05 0 0 12 1986 1988 1990 1992 1994 1996 1998 2000 2002

Ula

Block and Block 7/12 - production licence 019. Awarded 1965. production licence

Progress Government approval: May 1980 Production start-up: October 1986

Operator BP Norge AS

Licensees BP Norge AS 80% Svenska Petroleum Exploration A/S 15% Dong Norge AS 5%

Recoverable reserves Originally present: Remaining at 31.12.02: 79.2 mill scm oil 15.6 mill scm oil 4.0 bn scm gas 0.2 bn scm gas 2.7 mill tonnes NGL 0.2 mill tonnes NGL

Production Estimated production in 2003: Oil: 24 000 b/d NGL: 0.047 mill tonnes

Investment Total investment is likely to be NOK 23.9 bn (2003 value). NOK 19.4 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Sola

Proven in 1976, Ula lies in about 70 metres of water and has been developed with three conventional steel platforms – for processing, drilling and quarters respectively. Oil is carried by the Ula pipeline to Ekofisk and on through Norpipe to Teesside.

82 FIELDS IN PRODUCTION Oil: 1 000 b/d NGL: mill tonnes/year

100 0.2

80 0.15 60 0.1 40 20 0.05

0 0 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 12

Valhall (incl Valhall flanks and Valhall water injection)

Blocks and Block 2/8 - production licence 006B. Awarded 1965, carve-out 2000. production licences Block 2/11 - production licence 033B. Awarded 1969, carve-out 2001.

Progress Government approval: June 1977 Government approval: September 2000 (Valhall water injection) Government approval: November 2001 (Valhall flanks) Production start-up: October 1982

Operator BP Norge AS

Licensees BP Norge AS 28.09% (rounded off to two Amerada Hess Norge AS 28.09% decimal places) Enterprise Oil Norge AS 28.09% TotalFinaElf Exploration Norge AS 15.72%

Recoverable reserves Originally present: Remaining at 31.12.02: 166.9 mill scm oil 92.0 mill scm oil 30.3 bn scm gas 15.2 bn scm gas 4.2 mill tonnes NGL 1.7 mill tonnes NGL

Production Estimated production in 2003: Oil: 75 000 b/d NGL: 0.12 mill tonnes

Investment Total investment is likely to be NOK 47.7 bn (2003 value) NOK 36.2 bn (2003 value) had been invested at 31.12.02 Operating organisation Stavanger

Main supply base Phillipsbasen/Akerbasen, Tananger

Valhall has been developed in 70 metres of water with platforms for drilling, production/compression and quarters. Two 20-inch pipelines, for oil and gas respectively, link Valhall to the Ekofisk centre. In connection with the Ekofisk II development, a new 24-km gas line from Valhall ties directly into the Norpipe gas trunkline to Emden. Oil is piped via Ekofisk to Teesside. The Valhall flanks and Valhall water injection developments are expected to improve the recovery factor for the field to 42 per cent. Valhall flanks is being developed with two unstaffed platforms. Production from the south flank is due to start in the first quarter of 2003. A platform connected by a bridge to the existing installations is due to be installed in the summer of 2003 for Valhall water injection, which will come on stream later the same year.

FIELDS IN PRODUCTION 83 Oil: 1 000 b/d

jg 35 30 25 20 15 10 5 0 12 1999 2000 2001 2002 2003

Varg

Block and Block 15/12 - production licence 038. Awarded 1975. production licence

Progress Government approval: May 1996 Production start-up: December 1998

Operator Pertra AS

Licensees Pertra AS 70% Petoro AS1 30%

Recoverable reserves Originally present: Remaining at 31.12.02: 6.1 mill scm oil 0.6 mill scm oil

Production Estimated production in 2003: Oil: 12 000 b/d

Investment Total investment is likely to be NOK 5.5 bn (2003 value). NOK 5.2 bn (2003 value) had been invested at 31.12.02.

Operating organisation Oslo

Main supply base Tananger

1 Petoro AS serves as the licensee for the SDFI.

Varg was proven in 1984 and lies in 84 metres of water south of Sleipner East. The field has been developed with a wellhead platform and a production ship which provides integrated oil storage. These two units are linked by flexible flowlines for oil production as well as water and gas injection, and by umbilicals for power supply and control. The wellhead platform is normally unstaffed. Oil is transferred to shuttle tankers from the production ship via a discharging system at the stern of the latter.The production ship was sold in 1999 to Petroleum Geo Services (PGS), which also took over management responsibility for the vessel. The cessation plan for Varg was approved by the King in Council in November 2001, but the exact date for a final shutdown remains to be clarified.

84 FIELDS IN PRODUCTION 2˚ 4˚ 6˚ 62˚ 62˚ MåløyMåløy

269 270 206 12 Snorre FlorFFlorølorø 206 57 Sygna 268 268 280 Statfjord North 268 153 Murchison 33/9-6 Delta Vigdis 120 35/9-1 Gjøa Visund 35/8-1 195 248 Tordis 37 35/8-2 Statfjord 89 34/8-12 279 195 153

50 37 Gullfaks Gullfaks South 34/10-47 S 248 152 193 Kvitebjørn Fram 33/12-8 S Brent 174 61˚ 61˚ 50 34/10-23 Gamma 90 50 33/12-8 A

Huldra 54 52 52 Troll Mongstad 51 Veslefrikk 278 85 Oseberg East 53 85 53 55 Sture 30/6-26 Gamma West Oseberg Brage 30/6-17 Oseberg West Kollsnes 30/4-6 Hild 30/6-18 Kappa 55 85 Tune 40 190 185 30/7-2 30/9-19 79

BERGENBERGEN 190 Oseberg South 190 104

Åsgard Transport 171 Odin 272 35 60˚ 60˚ North East Frigg

Frigg Lille-Frigg 24 East Frigg 26

26 Statpipe 245 Frøy Vale

36 24/6-1 Peik Byggve Heimdal Skirne 25/5-5 24/6-2 102 88 245 24/9-6 25/4-3 Gekko 203 HHaugesundaugesund 24/9-5 27 Jotun 189

169 ipe Kårstø ipe II A ipe II B p 204 t 103 189 a 25/8-4 eep Balder Z eep Grane Z 28 Awarded acreage 25/11-16 0 40 80 Km

28 204 59˚ 59˚ 169 2˚ 4˚ Northern North Sea sector

The main areas in the northern part of Norway’s North Sea sector are Tampen, Troll/Oseberg, and Frigg/Heimdal. Tampen contains a number of fields, including Statfjord, Snorre, Gullfaks, Visund, Vigdis and Tordis. Several of these rank among Norway’s largest oil fields. Although this is a mature petroleum province, its resource potential remains considerable. Troll has a very important function in gas deliveries from the NCS, but has also become a substantial oil producer. The Oseberg area includes Brage and Veslefrikk as well as Oseberg itself. Oil production from this part of the NCS is declining, but will remain substantial for many years to come. Oseberg is set to increase its gas deliveries. Heimdal has developed into a gas centre which provides processing services for surrounding fields. Production from Frigg is likely to cease in 2004, after many years of operation.

FIELDS IN PRODUCTION 85 Oil: 1 000 b/d

0 12 1999 2000 2001 2002 2003

Balder (incl Ringhorne)

Blocks and Block 25/11 - production licence 001. Awarded 1965. production licences Block 25/8 - production licence 027. Awarded 1969. Block 25/8 - production licence 027C. Awarded 1969, carve-out 2000. Blocks 25/8 and 25/11 - production licence 169. Awarded 1991.

Progress Government approval: February 1996 Ringhorne approval: June 2000 Production start-up: October 1999

Operator Esso Expl & Prod Norway AS

Licensee Esso Expl & Prod Norway AS 100%

Recoverable reserves Originally present: Remaining at 31.12.02: 60.3 mill scm oil 48.0 mill scm oil 2.9 bn scm gas 2.9 bn scm gas

Production Estimated production in 2003: Oil: 68 000 b/d

Investment Total investment is likely to be NOK 23.1 bn (2003 value). NOK 19 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

Balder was proven in 1967 and lies about 85 km north of the Sleipner area and 190 km west of Stavanger. The water depth is roughly 125 metres. Balder has been developed with a production ship tied to subsea- completed wells. Oil is processed and stored on the ship before being transferred to shuttle tankers. The Storting approved the Ringhorne development in May 2000. Covering several structures close to Balder, it involves an integrated drilling, well and quarters platform with first-stage processing. This has been tied back to the Balder ship for further processing and export of the oil. The platform is supple- mented with two subsea wells – for production and water injection respectively – tied back directly to the ship. While the subsea producer came on stream in May 2001, the platform started production in early 2003. The Ringhorne and Balder pipeline system was approved by the government on 1 February 2003. This project involves three pipelines to transport oil and gas from the two fields to Jotun.

86 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

120 0.5

100 0.4 80 0.3 60 0.2 40 20 0.1 0 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 12

Brage

Blocks and Block 30/6 - production licence 053B. Awarded 1979, carve-out 1998. production licences Block 31/4 - production licence 055. Awarded 1979. Block 31/7 - production licence 185. Awarded 1991.

Progress Government approval: March 1990 Production start-up: September 1993

Operator Norsk Hydro Produksjon a.s

Licensees Norsk Hydro Produksjon a.s 20.00% (rounded off to two Paladin Resources Norge AS 20.00% decimal places) Esso Expl & Prod Norway AS 16.34% Petoro AS1 14.26% Statoil ASA 12.70% Fortum Petroleum AS 12.26% OER Oil AS 4.44%

Recoverable reserves Originally present: Remaining at 31.12.02: 45.4 mill scm oil 4.1 mill scm oil 2.0 bn scm gas 0.1 bn scm gas 0.7 mill tonnes NGL 0.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 33 000 b/d Gas: 0.06 bn scm NGL: 0.03 mill tonnes

Investment Total investment is likely to be NOK 17.5 bn (2003 value). NOK 16.7 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply base Mongstad

1 Petoro AS serves as the licensee for the SDFI.

The Brage field has been developed in 140 metres of water with an integrated steel production, drilling and quarters platform. Production began in 1993 and went off plateau in 1998. Oil goes by pipeline to Oseberg A for onward transmission through the Oseberg Transport System (OTS) to the Sture terminal near Bergen, while gas is carried in a line tied to Statpipe for onward transport. A plan for development and operation of the Sogne Fjord formation was approved in October 1998. One well in this formation is currently producing, and several more are under consideration.

FIELDS IN PRODUCTION 87 Gas: bn scm/year NGL: mill tonnes/year

14 0.05 12 0.04 10 8 0.03 6 0.02 4 0.01 2 0 0 12 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

Frigg

Block and Blocks 25/1 - production licence 024. Awarded 1969. production licences 60.82 per cent lies on the Norwegian side, 39.18 per cent in the UK sector.

Progress Government approval: June 1974 Production start-up: September 1977

Operator TotalFinaElf Exploration Norge AS

Licensees TotalFinaElf Exploration Norge AS 28.67% (rounded off to two Elf Exploration UK plc 26.12% decimal places) Norsk Hydro Produksjon a.s 19.99% Total Oil Marine plc 13.06% Statoil ASA 12.16%

Recoverable reserves Originally present: Remaining at 31.12.02: 115.9 bn scm gas 1.3 bn scm gas 0.5 mill scm condensate

Production Estimated production in 2003: Gas: 0.4 bn scm. Condensate: 2 000 scm Production is expected to cease in 2004.

Investment Total investment is likely to be NOK 36 bn (2003 value). NOK 36 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

88 FIELDS IN PRODUCTION 12

The unitisation agreed by the Frigg partners, which gives Norway a 60.82 per cent share, was approved by the UK and Norwegian authorities under a treaty between the two countries on joint exploitation. Production started in 1977 and reached plateau in October 1979. Frigg went off plateau in October 1987. Located in about 100 metres of water, the field installations also processed Frøy’s oil and gas from the summer of 1995 until the latter field ceased production in March 2001. In addition, Britain’s Alwyn field utilises the Frigg installations, while gas from North-East Frigg, Odin, East Frigg and Lille-Frigg was processed there until production from these fields ceased in May 1993, August 1994, December 1997 and March 1999 respectively. The government decided not to acquire the North-East Frigg, East Frigg, Odin and Lille-Frigg installations. A cessation plan for Frigg was submitted to the authorities in November 2001.

FIELDS IN PRODUCTION 89 Oil: 1 000 b/d Gas: bn scm/year

600 5 500 4 400 3 300 2 200 100 1 0 0

6 7 6 90 91 94 95 98 99 99 997 002 003 12 198 198 1988 1989 19 19 1992 1993 19 19 1 1 19 19 2000 2001 2 2

Gullfaks (incl Gullfaks West)

Blocks and Block 34/10 - production licence 050. Awarded 1978. production licences Block 34/10 - production licence 050B. Awarded 1995.

Progress Government approval: October 1981 (Gullfaks phase I – platforms A and B). Production start-up: December 1986

Operator Statoil ASA

Licensees Statoil ASA 61% Petoro AS1 30% Norsk Hydro Produksjon a.s 9%

Recoverable reserves Originally present: Remaining at 31.12.02: 335.3 mill scm oil 40.2 mill scm oil 22.3 bn scm gas 2.2 bn scm gas 2 mill tonnes NGL 0.5 mill tonnes NGL

Production Estimated production in 2003: Oil: 159 000 b/d

Investment Total investment is likely to be NOK 112.1 bn (2003 value). NOK 103.8 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply bases Coast Center Base, Sotra og Florø

1 Petoro AS serves as the licensee for the SDFI.

Gullfaks was discovered in 1978 and lies in 130-220 metres of water. The field has been developed with three concrete gravity based platforms. Gullfaks A and C are integrated production, drilling and quarters units, while oil and gas from Gullfaks B are piped to the A or C installations for further treatment and storage. Stabilised oil is stored in the A and C platforms and loaded into tankers via buoys. Gas is being injected back into Gullfaks from 2002.

90 FIELDS IN PRODUCTION 12

The Gullfaks installations form an important part of the infrastructure in the Tampen area. The wellstream from Tordis is transferred to and processed on Gullfaks C, while stabilised crude from Vigdis and Visund is stored on and shipped from the A platform. Development approval for the small Gullfaks West satellite was given by the King in Council in January 1993. This field is being drained by a horizontal well drilled from Gullfaks B. Draining Gullfaks Lunde through wells drilled from Gullfaks C was approved in November 1995, and this field came on stream in 1996. In recent years, Gullfaks A and C have been modified to receive and process oil and gas from Gullfaks South. This satellite has been developed with subsea wells remotely operated from the A platform (see the next section).

FIELDS IN PRODUCTION 91 Oil: 1 000 b/d Gas: bn scm/year

70 2.5 60 2 50 40 1.5 30 1 20 0.5 10 0 0 12 1999 2000 2001 2002 2003

Gullfaks South (incl Rimfaks and Gullveig)

Blocks and Block 34/10 - production licence 050. Awarded 1978. production licences Block 34/10 - production licence 050B. Awarded 1995. Block 33/12 - production licence 037B. Awarded 1973, carve-out 1998.

Progress Government approval (phase I): March 1996 Government approval (phase II): June 1998 Production start-up (phase I): October 1998 Production start-up (phase II): October 2001

Operator Statoil ASA

Licensees Statoil ASA 61% Petoro AS1 30% Norsk Hydro Produksjon a.s 9%

Recoverable reserves Originally present: Remaining at 31.12.02: 35.5 mill scm oil 22.6 mill scm oil 32.1 bn scm gas 29.1 bn scm gas 4.0 mill tonnes NGL 3.8 mill tonnes NGL

Production Estimated production in 2003: Oil: 56 000 b/d Gas: 2.32 bn scm NGL 0.27 mill tonnes

Investment Total investment is likely to be NOK 29.3 bn (2003 value). NOK 20.9 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply bases Coast Center Base, Sotra og Florø

1 Petoro AS serves as the licensee for the SDFI.

Gullfaks South, which also includes the separate Rimfaks and Gullveig structures, is a satellite to Gullfaks and lies in the same water depth. The licensees have pursued a phased development of Gullfaks South.

92 FIELDS IN PRODUCTION 12

Gullfaks South phase I embraces the production of oil and condensate. Associated gas is injected back into the reservoirs. This phase comprises eight subsea installations tied back to Gullfaks A for processing, storage and loading of oil and condensate. Phase II embraces production and export of the gas resources and associated liquids. The development solution is based on subsea installations tied back to Gullfaks A and C. Gas production from Gullfaks South began in the autumn of 2001. After processing, rich gas is transported to Kårstø via a pipeline which ties into Statpipe. After removal of the NGL, dry gas is piped on to continental Europe. Oil and condensate are stabilised, stored and loaded by existing facilities on the platforms. In connection with phase II, Gullfaks C has been upgraded to expand its gas processing and export capacity. A corresponding upgrade will be implemented on the A platform up to the autumn of 2003.

FIELDS IN PRODUCTION 93 Oil: 1 000 b/d Gas: bn scm/year

12 5 10 4 8 3 6 2 4 2 1 0 0

k 6 7 8 2 3 87 93 986 991 992 99 99 99 00 00 12 1 19 1988 1989 1990 1 1 19 1994 1995 1 1 1 1999 2000 2001 2 2

Heimdal

Block and Block 25/4 - production licence 036. Awarded 1971. production licence

Progress Government approval: June 1981 Production start-up: December 1985

Operator Norsk Hydro Produksjon a.s

Licensees Marathon Petroleum Norge A/S 23.80% (rounded off to two Petoro AS1 20.00% decimal places) Statoil ASA 20.00% Norsk Hydro Produksjon a.s 19.27% TotalFinaElf Exploration Norge AS 16.76% AS Ugland Rederi 0.17%

Recoverable reserves Originally present: Remaining at 31.12.02: 7.0 mill scm oil 0.8 mill scm oil 41.8 bn scm gas 0.2 bn scm gas

Production Estimated production in 2003: Oil: 1 000 b/d Gas: 0.25 bn scm Production is expected to cease in 2003. Heimdal will continue providing processing and transport services as a gas centre to 2010 and beyond.

Investment Total investment is likely to be NOK 19.5 bn (2003 value). NOK 19.5 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply base Dusavik

1 Petoro AS serves as the licensee for the SDFI.

The field was declared commercial in 1974, and the government exercised its option to secure participation in 1982. Heimdal has been developed with an integrated steel platform in 120 metres of water. In 1998, the MPE received development plans for the Heimdal gas centre, which involved installing a new riser platform as well as modifying and upgrading the existing installation. The MPE approved the plan for development and operation of the Heimdal gas centre in February 1999, and the project came on stream in 2000. It ensures long-term operation of the Heimdal platform by using its capacity to process gas from Hul- dra and other surrounding fields.

94 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

30 3.5 25 3 20 2.5 2 15 1.5 10 1 5 0.5 0 0 2001 2002 2003 12

Huldra

Blocks and Block 30/2 - production licence 051. Awarded 1979. production licences Block 30/3 - production licence 052B. Awarded 2001.

Progress Government approval: February 1999 Production start-up: November 2001

Operator Statoil ASA

Licensees Petoro AS1 31.96% (rounded off to two TotalFinaElf Exploration Norge AS 24.33% decimal places) Norske Conoco A/S 23.34% Statoil ASA 19.66% Paladin Resources Norge AS 0.50% Svenska Petroleum Exploration A/S 0.21%

Recoverable reserves Originally present: Remaining at 31.12.02: 5 mill scm oil 3.7 mill scm oil 12.9 bn scm gas 10.2 bn scm gas 0.1 mill tonnes NGL 0.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 25 000 b/d Gas: 3.2 bn scm NGL: 0.027 mill tonnes

Investment Total investment is likely to be NOK 6.9 bn (2003 value) NOK 6.8 bn (2003 value) had been invested at 31.12.02.

1 Petoro AS serves as the licensee for the SDFI.

Huldra was proven in 1982 and lies in 125 metres of water. It has been developed with a normally unstaffed wellhead platform remotely operated from Veslefrikk 16 km away. Condensate is piped to Veslefrikk B for processing and onward transport to the crude oil terminal at Sture through the Ose- berg Transport System (OTS). The rich gas is piped 145 km to the Heimdal field for processing and export to customers via either the Statpipe/Norpipe system to continental Europe or the Vesterled line to the UK.

FIELDS IN PRODUCTION 95 Oil: 1 000 b/d Gas: bn scm/year

140 0.35 120 0.3 100 0.25 80 0.2 60 0.15 40 0.1 20 0.05 0 0 12 1999 2000 2001 2002 2003

Jotun

Blocks and Block 25/8 - production licence 027B. Awarded 1969, carve-out 1999. production licences Block 25/7 - production licence 103B. Awarded 1985, carve-out 1998.

Progress Government approval: June 1997 Production start-up: October 1999

Operator Esso Expl & Prod Norway AS

Licensees Esso Expl & Prod Norway AS 45% Enterprise Oil Norge AS 45% Det Norske Oljeselskap AS 7% Petoro AS1 3%

Recoverable reserves Originally present: Remaining at 31.12.02: 29.3 mill scm oil 13.2 mill scm oil 0.7 bn scm gas 0.1 bn scm gas

Production Estimated production in 2003: Oil: 44 000 b/d Gas: 0.05 bn scm

Investment Total investment is likely to be NOK 11.1 bn (2003 value). NOK 10.1 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Dusavik

1 Petoro AS serves as the licensee for the SDFI.

Jotun comprises the Elli, Elli South and Tau West reservoirs, proven in 1994 and 1995. The field lies about 25 km north of Balder and 165 km west of Haugesund, in 126 metres of water. It has been developed with a floating production, storage and offloading (FPSO) unit and a wellhead platform. Ship and platform are tied together by flowlines for oil and gas production and for water injection, as well as power and control cables. The wellhead platform is normally unstaffed. Oil production is transported by shuttle tankers. Gas will be exported through a pipeline tied into the Statpipe system. From 2004, Jotun will also receive oil and gas from Balder and Ringhorne for processing and onward transport.

96 FIELDS IN PRODUCTION Oil: 1 000 b/d NGL: mill tonnes/year 60 0.12 50 0.1 40 0.08 30 0.06 20 0.04 10 0.02 0 0 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 12

Murchison

Block and Block 33/9 - production licence 037C. Awarded 2000. production licence The Norwegian share is 22.2 per cent, while the British share is 77.8 per cent.

Progress Production start-up: September 1980

Operator CNR International (UK) Limited

Licensees CNR International (UK) Limited 68.72% (rounded off to two Statoil ASA 11.52% decimal places) Ranger Oil (UK) Limited 9.08% Norske Conoco A/S 2.68% Esso Expl & Prod Norway AS 5.50% A/S Norske Shell 2.22% Enterprise Oil Norge AS 0.23%

Recoverable reserves Originally present: Remaining at 31.12.02: (Norwegian share) 14.2 mill scm oil 1.1 mill scm oil 0.4 bn scm gas 0.1 bn scm gas 0.4 mill tonnes NGL 0.1 mill tonnes NGL

Production Estimated production in 2003: (Norwegian share) Oil: 3 000 b/d NGL: 2 000 tonnes

Investment The Norwegian share of total investment is likely to be NOK 7.6 bn (2003 value). NOK 7.4 bn (2003 value) had been invested at 31.12.02.

Operating organisation Aberdeen, Scotland

Main supply base Peterhead, Scotland

An integrated steel production, drilling and quarters platform has been installed on Murchison, which was discovered in August 1975. A unitisation agreement for Murchison was concluded by its British and Norwegian licensees in 1979. Both Norwegian and UK shares of the oil and NGL are landed through the Brent system to Sullom Voe in Shetland, with the gas piped to St Fergus on the Scottish mainland. CNR International (UK) took over as operator in 2002 from Kerr McGee North Sea (UK) Ltd.

FIELDS IN PRODUCTION 97 Oil: 1 000 b/d Gas: bn scm/year

600 3.5 500 3 2.5 400 2 300 1.5 200 1 100 0.5 0 0 12 1986 1988 1990 1992 1994 1996 1998 2000 2002

Oseberg (incl Oseberg West, Oseberg East and Oseberg South)

Blocks and Block 30/6 - production licence 053. Awarded 1979. production licences Block 30/9 - production licence 079, awarded 1982, and production licence 104, awarded 1985. Block 30/12 - production licence 171 B. Awarded 2000

Progress Government approval: June 1984 Oseberg West approval: December 1988 Oseberg East approval: October 1996 Oseberg South approval: June 1997 Production start-up: December 1988

Operator Norsk Hydro Produksjon a.s

Licensees Norsk Hydro Produksjon a.s 34.0% (rounded off to two Petoro AS1 33.6% decimal places) Statoil ASA 15.3% TotalFinaElf Exploration Norge AS 10.0% Mobil Development Norway A/S 4.7% Norske Conoco A/S 2.4%

Recoverable reserves Originally present: Remaining at 31.12.02: 432.1 mill scm oil 108.4 mill scm oil 103.8 bn scm gas 95.2 bn scm gas

Production Estimated production in 2003: Oil: 279 000 b/d Gas: 2.9 bn scm

Investment Total investment is likely to be NOK 103.7 bn (2003 value). NOK 91.1 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply base Mongstad

1 Petoro AS serves as the licensee for the SDFI.

98 FIELDS IN PRODUCTION 12

In connection with the sale of SDFI assets in 2002, licence interests were harmonised in the Oseberg area – the Oseberg Unit (Oseberg, Oseberg West and Oseberg East) and the Oseberg South Unit. This harmonisation was intended to ensure more effective overall development of the area across the underlying production licence boundaries.

Most of the reserves in the Oseberg area belonged to the original Oseberg Unit. After many years of production, this field now has oil reserves corresponding roughly to those in Oseberg South. But it continues to hold the great bulk of gas reserves in the area.

The original field is expected to account for almost a third of production from the Oseberg area in 2003.

The first development phase for Oseberg comprised a two-platform field centre. Oseberg A is a production and quarters platform on a concrete gravity base structure, while Oseberg B is a drilling and injection platform with a steel jacket. The second development phase embraced Oseberg C, a steel production, drilling and quarters platform which stands roughly 14 km north of the field centre. Total processing capacity for Oseberg is about 500 000 barrels of oil per day.

The platforms stand in around 100 metres of water. Reservoir pressure in Oseberg is maintained by gas, water, and water alternating gas (WAG) injection. Injection gas was received by Oseberg from the Togi subsea module on Troll until 2002. Gas from the Oseberg West satellite is injected in the phase I area.

Oil from Oseberg as well as Oseberg South, Oseberg East, Brage and Veslefrikk is piped through the Ose- berg Transport System (OTS) to Sture near Bergen.

Oseberg D, a steel platform with gas processing and export facilities, was tied to the field centre by a bridge in the spring of 1999. Gas deliveries to continental Europe began from Oseberg in October 2000 through a new pipeline which ties into the Statpipe system at Heimdal. Gas and condensate from the Tune field is piped to the field centre. After removal of the condensate, the gas will be injected into Oseberg.

The Oseberg East and Oseberg South satellites are also tied back to the field centre installations for oil and gas processing.

Comprising several structures south of Oseberg, the Oseberg South field was proven during 1984 in about 100 metres of water. Six of its structures are included in the approved development plan. The latter involves

FIELDS IN PRODUCTION 99 12

a platform for partial processing of the oil before it is piped to the Oseberg field centre for further processing and transport to land through the Oseberg Transport System (OTS) line. Gas production is injected back underground, and possible export of these reserves will occur in a later phase. The northern part of the field is being produced through wells drilled from the Oseberg field centre.

Oil production from Oseberg South began in February 2000 through a well drilled from the field centre. The platform came on stream in September 2000 and is expected to continue producing until 2028.

Located in 160 metres of water in the north-eastern part of the unitised Oseberg field and south of Veslefrikk, Oseberg East was proven in 1981 and has been developed with a platform for quarters, drilling and first-stage separation of oil, water and gas. Crude is piped to Oseberg A for further processing and onward transport via the Oseberg Transport System (OTS) to Sture near Bergen.

100 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

250 1.2 200 1 0.8 150 0.6 100 0.4 50 0.2 0 0 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 12

Snorre (incl Snorre B)

Blocks and Block 34/4 - production licence 057. Awarded 1979. production licences Block 34/7 - production licence 089. Awarded 1984.

Progress Government approval: May 1988 Production start-up: August 1992

Operator Statoil ASA

Licensees Petoro AS1 30.00% (rounded off to two Norsk Hydro Produksjon a.s 17.65% decimal places) Statoil ASA 14.40% Esso Expl & Prod Norway AS 11.16% Idemitsu Petroleum Norge AS 9.60% RWE Dea Norge AS 8.88% TotalFinaElf Exploration Norge AS 5.95% Amerada Hess Norge AS 1.18% Enterprise Oil Norge AS 1.18%

Recoverable reserves Originally present: Remaining at 31.12.02: 232.0 mill scm oil 127.8 mill scm oil 8.8 bn scm gas 4.3 bn scm gas 6.2 mill tonnes NGL 3.0 mill tonnes NGL

Production Estimated production in 2003: Oil: 236 000 b/d Gas: 0.36 bn scm NGL: 0.26 mill tonnes

Investment Total investment is likely to be NOK 67.3 bn (2003 value). NOK 53.6 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply base Florø

1 Petoro AS serves as the licensee for the SDFI.

FIELDS IN PRODUCTION 101 12

Proven in 1979, Snorre lies east of Statfjord in about 300-350 metres of water. Its southern area has been developed with a tension leg platform and a subsea production system. This part of the field con- tained about 150 mill scm of Snorre’s original recoverable oil reserves. A plan for development and operation of the northern part of the field (Snorre B) was approved in June 1998. This project involves a semi-submersible drilling and production platform, which came on stream in June 2001. Oil and gas from Snorre are piped to Statfjord for final processing, storage and export.

102 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year 5

0 0 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 12

Statfjord

Blocks and Blocks 33/9 and 33/12 - production licence 037. Awarded 1973. production licence Norway’s share of the field is 85.47 per cent, Britain’s is 14.53 per cent.

Progress Government approval: 1976 Production start-up: November 1979

Operator Statoil ASA

Licensees Statoil ASA 44.34% (rounded off to two Esso Expl & Prod Norway AS 21.37% decimal places) Norske Conoco A/S 10.33% A/S Norske Shell 8.55% Conoco (UK) Ltd 4.84% Chevron UK Ltd 4.84% BP Petroleum Development Ltd 4.84% Enterprise Oil Norge AS 0.89%

Recoverable reserves Originally present: Remaining at 31.12.02: (Norwegian share) 561.4 mill scm oil 34.5 mill scm oil 58.4 bn scm gas 12.0 bn scm gas 14.4 mill tonnes NGL 3.9 mill tonnes NGL

Production Estimated production in 2003: (Norwegian share) Oil: 126 000 b/d Gas: 1.71 bn scm NGL: 0.42 mill tonnes

Investment The Norwegian share of total investment is likely to be NOK 129.7 bn (2003 value). NOK 110.5 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply bases Coast Center Base, Sotra and Florø

FIELDS IN PRODUCTION 103 12

Proven in 1974, Statfjord lies in about 145 metres of water and extends into the UK North Sea. It has been developed with three fully-integrated platforms supported by gravity base structures featuring concrete storage cells. These installations have a combined processing capacity of 850 000 barrels per day. Each platform is tied to a buoy for loading stabilised oil into tankers. The platforms came on stream in November 1979, November 1982 and June 1985 respectively.

Gas sales began in October 1985. Norway’s share has been sold to a consortium of European buyers and is piped to Emden in Germany via the Statpipe/Norpipe system. The UK share of gas output has been sold to British Gas, and is landed in the UK via the Far North Liquids and Associated Gas System (Flags). Oil transport is organised by K/S Statfjord Transport, in which Statoil has a 50 per cent interest.

A unitisation agreement has been signed between the UK and Norwegian licensees. The operatorship for production licence 037 and the unitised field was transferred from Mobil to Statoil on 1 January 1987.

Oil and gas from Snorre, Sygna, Statfjord East and Statfjord North are processed on and exported from the Statfjord installations.

104 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

80 0.6 70 0.5 60 50 0.4 40 0.3 30 0.2 20 10 0.1 0 0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 12

Statfjord North

Block and Block 33/9 - production licence 037. Awarded 1973. production licence

Progress Government approval: December 1990 Production start-up: January 1995

Operator Statoil ASA

Licensees Petoro AS1 30.00% (rounded off to two Statoil ASA 21.88% decimal places) Esso Expl & Prod Norway AS 25.00% Norske Conoco A/S 12.08% A/S Norske Shell 10.00% Enterprise Oil Norge AS 1.04%

Recoverable reserves Originally present: Remaining at 31.12.02: 38.4 mill scm oil 13.1 mill scm oil 1.9 bn scm gas 0.5 bn scm gas 0.8 mill tonnes NGL 0.4 mill tonnes NGL

Production Estimated production in 2003: Oil: 41 000 b/d Gas: 0.16 bn scm NGL: 0.07 mill tonnes

Investment Total investment is likely to be NOK 8.3 bn (2003 value). NOK 7 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply bases Coast Center Base, Sotra

1 Petoro AS serves as the licensee for the SDFI.

Discovered in 1977, Statfjord North is about 17 km north of Statfjord. It has been developed with subsea installations in 250-290 metres of water, tied back to Statfjord C for processing and export.

FIELDS IN PRODUCTION 105 Oil: 1 000 b/d Gas: bn scm/year

80 0.14 70 0.12 60 0.1 50 0.08 40 0.06 30 20 0.04 10 0.02 0 0 12 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Statfjord East

Blocks and Block 33/9 - production licence 037. Awarded 1973. production licences Block 34/7 - production licence 089. Awarded 1984.

Progress Government approval: December 1990 Production start-up: September 1994

Operator Statoil ASA

Licensees Petoro AS1 30.00% (rounded off to two Statoil ASA 25.05% decimal places) Esso Expl & Prod Norway AS 17.70% Norsk Hydro Produksjon a.s 6.64% Norske Conoco A/S 6.04% A/S Norske Shell 5.00% Idemitsu Petroleum Norge AS 4.80% TotalFinaElf Exploration Norge AS 2.80% RWE Dea Norge AS 1.40% Enterprise Oil Norge AS 0.52%

Recoverable reserves Originally present: Remaining at 31.12.02: 35.0 mill scm oil 8.7 mill scm oil 2.6 bn scm gas 0.6 bn scm gas 1.1 mill tonnes NGL 0.6 mill tonnes NGL

Production Estimated production in 2003: Oil: 29 000 b/d Gas: 0.21 bn scm NGL: 0.88 mill tonnes

Investment Total investment is likely to be NOK 7.7 bn (2003 value). NOK 6.2 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stavanger

Main supply bases Coast Center Base, Sotra

1 Petoro AS serves as the licensee for the SDFI.

Statfjord East was discovered in 1976 and lies about seven km north-east of Statfjord. It has been developed with subsea installations in 150-190 metres of water, tied back to Statfjord C for processing and export.

106 FIELDS IN PRODUCTION Oil: 1 000 b/d

40 30

0 2001 2002 2003 12

Sygna

Blocks and Block 33/9 - production licence 037. Awarded 1973. production licences Block 34/7 - production licence 089. Awarded 1984.

Progress Government approval: April 1999 Production start-up: August 2000

Operator Statoil ASA

Licensees Petoro AS1 30.00% (rounded off to two Statoil ASA 24.73% decimal places) Esso Expl & Prod Norway AS 18.48% Norske Conoco A/S 6.65% Norsk Hydro Produksjon a.s 5.98% A/S Norske Shell 5.50% Idemitsu Petroleum Norge AS 4.32% TotalFinaElf Exploration Norge AS 2.52% RWE Dea Norge AS 1.26% Enterprise Oil Norge AS 0.57%

Recoverable reserves Originally present: Remaining at 31.12.02: 11.0 mill scm oil 6.0 mill scm oil

Production Estimated production in 2003: Oil: 26 000 b/d

Investment Total investment is likely to be NOK 2.5 bn (2003 value). NOK 1.9 bn (2003 value) had been invested at 31.12.02

Operating organisation Stavanger

Main supply base Florø

1 Petoro AS serves as the licensee for the SDFI.

Proven in 1996, this field straddles the boundary between production licences 037 (Statfjord) and 089 (Snorre). Sygna has been developed with a subsea production system tied back to Statfjord C. Water injection capacity to the Statfjord North area was upgraded in 1999 in order to supply Sygna with injection water.

FIELDS IN PRODUCTION 107 Oil: 1 000 b/d Gas: bn scm/year

100 0.5 80 0.4 60 0.3 40 0.2 20 0.1 0 0 12 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Tordis (incl Tordis East and Borg)

Block and Block 34/7 - production licence 089. Awarded 1984. production licence

Progress Government approval: May 1991 Production start-up: June 1994

Operator Statoil ASA

Licensees Petoro AS1 30.00% Statoil ASA 28.22% Norsk Hydro Produksjon a.s 13.28% Esso Expl & Prod Norway AS 10.50% Idemitsu Petroleum Norge AS 9.60% TotalFinaElf Exploration Norge AS 5.60% RWE Dea Norge AS 2.80%

Recoverable reserves Originally present: Remaining at 31.12.02: 54.5 mill scm oil 18.4 mill scm oil 4.4 bn scm gas 1.6 bn scm gas 1.5 mill tonnes NGL 0.7 mill tonnes NGL

Production Estimated production in 2003: Oil: 63 000 b/d Gas: 0.34 bn scm NGL: 0.109 mill tonnes

Investment Total investment is likely to be NOK 9.5 bn (2003 value). NOK 8.4 bn (2003 value) had been invested at 31.12.02

Operating organisation Stavanger

Main supply base Florø

1 Petoro AS serves as the licensee for the SDFI.

108 FIELDSFELT IIN PRODUKSJON PRODUCTION 12

The Tordis area embraces Tordis East and Borg as well as Tordis itself. Lying between Snorre and Gullfaks, Tordis was discovered in 1987 and came on stream in July 1994. A subsea development in about 200 metres of water is tied back to Gullfaks C, where the wellstream is processed.

Tordis East, Borg and another structure (STUJ) have been developed with subsea-completed wells tied back to the Tordis production facilities, and came on stream in December 1998, July 1999 and December 2001 respectively.

FIELDS IN PRODUCTION 109 Gas: bn scm/year NGL: mill tonnes/year

30 0.6 25 0.5 20 0.4 15 0.3 10 0.2 5 0.1 0 0 12 1996 1997 1998 1999 2000 2001 2002 2003

Troll phase I

Blocks and Block 31/2 - production licence 054. Awarded 1979. production licences Blocks 31/3, 31/5 and 31/6 - production licence 085. Awarded 1983. Blocks 31/3 and 31/6 - production licence 085C. Awarded 2002

Progress Government approval: December 1986 Production start-up: February 1996

Operator A/S Norsk Shell was operator for the development phase. Statoil ASA is operator for the production phase.

Licensees Petoro AS1 56.00% (rounded off to two Statoil ASA 20.80% decimal places) Norsk Hydro Produksjon a.s 9.78% A/S Norske Shell 8.10% TotalFinaElf Exploration Norge AS 3.69% Norske Conoco A/S 1.62%

Recoverable reserves Originally present: Remaining at 31.12.02: 1 325.7 bn scm gas 1 188.8 bn scm gas 31.6 mill tonnes NGL 31.6 mill tonnes NGL 1.6 mill scm condensate

Production Estimated production in 2003: Gas: 24.3 bn scm NGL: 0.5 mill tonnes

Investment Total investment is likely to be NOK 55.3 bn (2003 value). NOK 46.2 bn (2003 value) had been invested at 31.12.02.

Transport Gas from Troll is transported from Kollsnes through Zeepipe to Zeebrugge and Statpipe/Norpipe to Emden. The Franpipe line to Dunkerque has also been used since 1998. Condensate is shipped from Mongstad.

Operating organisation Bergen

Main supply base Ågotnes

1 Petoro AS serves as the licensee for the SDFI.

110 FIELDS IN PRODUCTION 12

Discovered in 1979, Troll lies about 65 km off Kollsnes near Bergen and comprises two main structures: Troll East and Troll West. The first of these primarily occupies blocks 31/3 and 31/6, while most of Troll West is found in block 31/2. Roughly two-thirds of the field’s recoverable gas reserves are thought to lie in Troll East.

A staged development has been pursued, with phase I covering gas reserves in the eastern region and phase II focusing on the oil reserves in Troll West. Phase III will cover gas reserves in the latter area.

The original phase I plan, approved in 1986, called for an integrated production, drilling and quarters platform in 330 metres of water, but this was amended in the spring of 1990 to a single wellhead platform and a land-based processing plant at Kollsnes near Bergen. The authorities approved these revised proposals in December 1990.

The processing plant at Kollsnes could be expanded to handle production from a development of the gas reserves in Troll West. Condensate is piped to the Vestprosess facility at Mongstad.

FIELDS IN PRODUCTION 111 Oil: 1 000 b/d

400

300

200

100

0 12 1995 1996 1997 1998 1999 2000 2001 2002 2003

Troll phase II

Progress Government approval: May 1992 Production start-up: September 1995

Operator Norsk Hydro Produksjon a.s

Recoverable reserves Originally present: Remaining at 31.12.02: 224.3 mill scm oil 106.7 mill scm oil Gas reserves are included under Troll phase I.

Production Estimated production in 2003: Oil: 344 000 b/d.

Investment Total investment is likely to be NOK 63.7 bn (2003 value). NOK 58.6 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply base Mongstad

1 Petoro AS serves as the licensee for the SDFI.

112 FIELDS IN PRODUCTION 12

A thin oil layer underlies the whole Troll field, but is only sufficiently thick for commercial recovery in the Troll West region. The latter divides into oil and gas provinces, where the thickness of the oil- bearing zones is 22-27 and 11-14 metres respectively. Test production from the two provinces in 1990 and 1991 yielded positive results.

Crude is being produced from the oil province with horizontally-drilled wells tied back to the Troll B floating production platform. Eighteen of 22 planned production wells are currently in operation, together with one gas injector. The crude is landed through Troll Oil Pipeline I to the terminal at Mongstad near Bergen. Associated gas is exported via the A platform on Troll East.

Oil production from the first Troll B well cluster in the gas province began during November 1995. At 31 December 2001, 29 of 33 planned wells tied back to Troll B were in operation in the gas province.

The floating Troll C production platform came on stream in late October 1999 to recover oil from the northern part of the gas province. At 31 December 2001, 30 of 55 production wells were in operation in addition to a water injector for the Troll Pilot project. Oil from Troll C is landed through Troll Oil Pipeline II to Mongstad, with associated gas exported via Troll A.

Testing of the Troll Pilot, a subsea separation plant, began in the summer of 2000.

FIELDS IN PRODUCTION 113 12

Tune

Blocks and Block 30/5 - production licence 034. Awarded 1969. production licences Block 30/6 - production licence 053. Awarded 1979. Block 30/8 - production licence 190. Awarded 1993.

Progress Government approval: December 1999 Production start-up: 28 November 2002

Operator Norsk Hydro Produksjon a.s

Licensees Petoro AS1 40% Norsk Hydro Produksjon a.s 40% TotalFinaElf Exploration Norge AS 20%

Recoverable reserves Originally present: Remaining at 31.12.02: 6.1 mill scm oil 6.0 mill scm oil 22.9 bn scm gas 22.9 bn scm gas 0.1 mill tonnes NGL 01. mill tonnes NGL Gas reserves are included under Troll phase I. Production Estimated production in 2003: Oil: 24 000 b/d Gas 3.0 bn scm, NGL 0.03 tonnes

Investment Total investment is likely to be NOK 4.7 bn (2003 value). NOK 3.6 bn (2003 value) had been invested at 31.12.02.

1 Petoro AS serves as the licensee for the SDFI.

Tune is a gas and condensate field proven in 1995, about 10 km west of the Oseberg field centre. The bulk of its reserves lie in production licence 190, but part of them extends into production licences 034 and 053. Licence interests in 034 and 190 are the same, and the Tune licensees have purchased production rights for the reserves extending into 053. Phase I of the development covers four production wells drilled from a subsea installation centrally placed on the field and tied back to Oseberg D through two 12-inch flowlines and an umbilical. A Tune receiving module has been built on Oseberg D. Tune condensate will be stabilised at the Oseberg field centre and piped to Sture through the Oseberg Transport System. Gas from the field is due to be injected in Oseberg, but the Tune licensees will receive sales gas in exchange from the Oseberg Unit at the inlet to the Oseberg Gas Transport system.

114 FIELDS IN PRODUCTION 12

Vale

Block and Block 25/4 - production licence 036. Awarded 1971. production licence

Progress Government approval: March 2001 Production start-up: 31 May 2002

Operator Norsk Hydro Produksjon a.s

Licensees Marathon Petroleum Norge A/S 46.90% (rounded off to two Norsk Hydro Produksjon a.s 28.53% decimal places) TotalFinaElf Exploration Norge AS 24.24% AS Ugland Rederi 0.32%

Recoverable reserves Originally present: Remaining at 31.12.02: 2.6 mill scm oil 2.5 mill scm oil 2.2 bn scm gas 2.2 bn scm gas Gas reserves are included under Troll phase I.

Production Estimated production in 2003: Oil: 15 000 b/d Gas: 0.54 bn scm.

Investment Total investment is likely to be NOK 1.6 bn (2003 value). NOK 1.5 bn (2003 value) had been invested at 31.12.02.

Proven in 1991, Vale lies 16 km north of Heimdal and has been developed with a single subsea well, a seabed template and a 16.5-km flowline. The latter is tied back to the Heimdal platform for processing the wellstream. Existing pipeline systems are being used to export the field’s output.

FIELDS IN PRODUCTION 115 Oil: 1 000 b/d Gas: bn scm/year

100 1.2 80 1 0.8 60 0.6 40 0.4 20 0.2 0 0 12 1990 1992 1994 1996 1998 2000 2002

Veslefrikk

Blocks and Block 30/3 - production licence 052. Awarded 1979. production licences Block 30/6 - production licence 053. Awarded 1979.

Progress Government approval: June 1987 Production start-up: December 1989

Operator Statoil ASA

Licensees Petoro AS1 37.0% Statoil ASA 18.0% TotalFinaElf Exploration Norge AS 18.0% RWE Dea Norge AS 13.5% Paladin Resources Norge AS 9.0% Svenska Petroleum Exploration A/S 4.5%

Recoverable reserves Originally present: Remaining at 31.12.02: 55.0 mill scm oil 13.2 mill scm oil 3.0 bn scm gas 0.9 bn scm gas 1.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 33 000 b/d

Investment Total investment is likely to be NOK 17.4 bn (2003 value). NOK 15.6 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply bases Coast Center Base, Sotra and Florø

1 Petoro AS serves as the licensee for the SDFI.

Proven in 1981, Veslefrikk has been developed with the fixed A wellhead platform and the B semi-submersible for processing and quarters in about 175 metres of water. The oil is piped to Oseberg A for onward transmission through the Oseberg Transport System (OTS) to the terminal at Sture near Ber- gen, while the gas travels via Statpipe. Veslefrikk B was taken to land in the summer of 1999 to reinforce its steel hull and to make the modifi- cations required to receive Huldra condensate from the autumn of 2001. The normally unstaffed platform on the latter field is remotely operated from Veslefrikk B.

116 FIELDS IN PRODUCTION Oil: 1 000 b/d

100 80 60 40 20 0 1997 1998 1999 2000 2001 2002 2003 12

Vigdis

Block and Block 34/7 - production licence 089. Awarded 1984. production licence

Progress Government approval: December 1994 Production start-up: January 1997

Operator Statoil ASA

Recoverable reserves Originally present: Remaining at 31.12.02: 39.7 mill scm oil 17.4 mill scm oil 3.2 bn scm gas 3.2 bn scm gas

Production Estimated production in 2003: Oil: 43 000 b/d

Investment Total investment is likely to be NOK 12.1 bn (2003 value). NOK 7.6 bn (2003 value) had been invested at 31.12.02.

1 Petoro AS serves as the licensee for the SDFI.

Located between Snorre and Gullfaks, Vigdis was discovered in 1986 and began production in January 1997. It has been developed with subsea installations in 280 metres of water. These are tied back to Snorre, where the petroleum is processed. Stabilised crude oil is transferred via a dedicated pipeline to Gullfaks A for storage and loading into tankers. The Vigdis extension project was approved by the King in Council in December 2002, and is expected to come on stream around the end of 2003. This development extends production from the existing field.

FIELDS IN PRODUCTION 117 Oil: 1 000 b/d

60 50 40 30 20 10 0 12 1999 2000 2001 2002 2003

Visund

Block and Block 34/8 - production licence 120. Awarded 1985. production licence

Progress Government approval: March 1996 Production start-up: April 1999

Operator Statoil ASA

Licensees Statoil ASA 32.9% Petoro AS1 30.0% Norsk Hydro Produksjon a.s 20.3% Norske Conoco A/S 9.1% TotalFinaElf Exploration Norge AS 7.7%

Recoverable reserves Originally present: Remaining at 31.12.02: 38.4 mill scm oil 30.5 mill scm oil 50.3 bn scm gas 50.3 bn scm gas 6.7 mill tonnes NGL 6.7 mill tonnes NGL

Production Estimated production in 2003: Oil: 50 000 b/d

Investment Total investment is likely to be NOK 19.3 bn (2003 value). NOK 14.8 bn (2003 value) had been invested at 31.12.02.

Operating organisation Bergen

Main supply base Florø

1 Petoro AS serves as the licensee for the SDFI.

Proven in 1986, Visund lies east of Snorre. It has been developed with a steel-hulled floating platform for production, drilling and quarters, with oil piped to Gullfaks A for storage and export. Visund gas export was approved by the government in October 2002. This project involves a new pipeline from Visund to tie into the Kvitebjørn gas pipeline for onward transport to Kollsnes. The gas will be processed in the NGL plant at Kollsnes and transported through the existing pipeline to continental Europe.

118 FIELDS IN PRODUCTION 6˚ 8˚ 10˚ 12˚

67˚ 6707/10-1 67˚ 215 215 217 218 218

NORDLAND III NORD- 215 215 LAND V

283 AND II NORDL 86 286 VØRING 285 2 BASIN l NORD- LAND l 283 283 283 283 200 200 128 128 Sandnes-Sandnes- 127 6608/10-8 Stær 128 sjøen 66˚ 284 6608/11-2 Falk sjsjøenen 6507/2-2 6608/10-6 Svale 66˚ Norne 6507/3-1 Alve 159 213 282 282 6507/3-3 Idun 259 259 261 261 VØRING 6507/5-1 Skarv BASIN II 6507/5-3 Snadd 6506/6-1 282 282 282 259 211 211 212 212 NORDLAND IV 124 BrBBrønnøysundrønnnnøyysundsund 260 6507/7-13 Heidrun 210 210 260 95

94 6506/11-7 263 sgard 65˚ 134 210 210 65˚ 256 94 263 Kristin 6506/12-3 Lysing 256 199 6506/11-2 Lange 74 6406/1-1 6407/1-3 Tyrihans North 6406/2-7 Erlend 6406/3-2 Trestakk 210 210 6407/1-2 Tyrihans South 6406/2-1 Lavrans 199 91 6406/2-6 Ragnfrid 92 Mikkel TRØNDELAG l

281 255 255 6407/9-9 132 NamsosNamsos 93 254 Njord Draugen 281 255 132

64˚ 254 281 64˚ Haltenpip

209 209 TRØNDELAG ll e

209 209 6305/5-1 Stjørdal Ormen Lange TRONDHEIMTRONDHEIM 252 208 208 209 209 Tjeldbergodden

63˚ 63˚ KristiansundKKrristiansundistiansund MØRE l

ansport Tr MoldeMolde Awarded acreage

Åsgard ÅlesundÅllesundesund 0 40 80 Km

6˚ 8˚ 10˚ 12˚ Norwegian Sea

The Norwegian Sea was opened for exploration in connection with the fifth offshore licensing round in 1979. The Draugen oil field was the first Norwegian Sea discovery to be developed, and came on stream in October 1993. Heidrun, Njord, Norne and Åsgard have since started production, while plans for development and operation (PDOs) for Kristin and Mikkel were approved in 2001. About 24 per cent of Norway’s oil production derived from the Norwegian Sea in 2002. This region also contains substantial gas resources.

FIELDS IN PRODUCTION 119 Oil: 1 000 b/d Gas: bn scm/year

250 0.35 0.3 200 0.25 150 0.2 100 0.15 0.1 50 0.05 0 0 12 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Draugen

Block and Block 6407/9 - production licence 093. Awarded 1984. production licence

Progress Government approval: December 1988 Production start-up: October 1993

Operator A/S Norske Shell

Licensees Petoro AS1 47.88% A/S Norske Shell 26.20% BP Norge AS 18.36% Chevron Texaco Norge AS 7.56%

Recoverable reserves Originally present: Remaining at 31.12.02: 134.5 mill scm oil 46.6 mill scm oil 6.0 bn scm gas 5.5 bn scm gas 1.7 mill tonnes NGL 1.1 mill tonnes NGL

Production Estimated production in 2003: Oil: 177 000 b/d Gas: 0.31 bn scm NGL: 0.31 mill tonnes

Investment Total investment is likely to be NOK 27 bn (2003 value). NOK 24.5 bn (2003 value) had been invested at 31.12.02.

Operating organisation Kristiansund

Main supply base Kristiansund

1 Petoro AS serves as the licensee for the SDFI.

Draugen was discovered in 1984 in 251 metres of water, and has been developed with a concrete monotow- er gravity base structure supporting an integrated topside. The field is currently producing from six horizontal platform wells. Reserves consist mainly of oil. Associated gas is piped to Kårstø via a tie-in with the Åsgard Transport trunkline. Oil is loaded into shuttle tankers on the field via two flowlines which link the platform with a floating loading buoy. Garn West, a separate oil deposit in the Draugen field, was developed and brought on stream in 2001 with two subsea wells tied back via a flexible flowline to the Draugen platform. A similar structure, Rogn South, was developed and brought on stream via Garn West during 2002.

120 FIELDS IN PRODUCTION Oil: 1 000 b/d Gas: bn scm/year

250 1.6 1.4 200 1.2 150 1 0.8 100 0.6 50 0.4 0.2 0 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 12

Heidrun

Blocks and Block 6507/7 - production licence 095. Awarded 1984. production licences Block 6507/8 - production licence 124. Awarded 1986.

Progress Government approval: May 1991 Production start-up: October 1995

Operator Statoil ASA

Licensees Petoro AS1 58.16% (rounded off to two Norske Conoco A/S 24.29% decimal places) Statoil ASA 12.43% Fortum Petroleum AS 5.12%

Recoverable reserves Originally present: Remaining at 31.12.02: 180 mill scm oil 98.3 mill scm oil 29.9 bn scm gas 25.4 bn scm gas 1.8 mill tonnes NGL 1.7 mill tonnes NGL

Production Estimated production in 2003: Oil: 169 000 b/d Gas: 1.3 bn scm NGL: 0.1 mill tonnes

Investment Total investment is likely to be NOK 63.2 bn (2003 value). NOK 51.1 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stjørdal

Main supply base Kristiansund

1 Petoro AS serves as the licensee for the SDFI.

The Heidrun field was discovered in 1985 and lies in some 350 metres on the Halten Bank off mid- Norway. A revised development plan submitted in December 1989 was approved by the government, and embraces a concrete tension leg platform (TLP). Heidrun’s northern flank is being developed with subsea installations in order to phase in resources in this part of the field. Associated gas from Heidrun is carried in the dedicated Haltenpipe line to Tjeldbergodden in mid-Nor- way for conversion to methanol. The separate Heidrun gas export pipeline ties into the Åsgard Transport system to transport gas to Kårstø.

FIELDS IN PRODUCTION 121 Oil: 1 000 b/d

0 12 1997 1998 1999 2000 2001 2002 2003

Njord

Blocks and Block 6407/7 - production licence 107. Awarded 1985. production licences Block 6407/10 - production licence 132. Awarded 1987.

Progress Government approval: June 1995 Production start-up: September 1997

Operator Norsk Hydro Produksjon a.s

Licensees Norsk Hydro Produksjon a.s 20.0% Gaz de France Norge AS 20.0% Mobil Development Norway A/S 20.0% Norske Conoco A/S 15.0% Paladin Resources Norge AS 15.0% Petoro AS1 7.5% OER Oil AS 2.5%

Recoverable reserves Originally present: Remaining at 31.12.02: 23.9 mill scm oil 9.6 mill scm oil

Production Estimated production in 2003: Oil: 36 000 b/d.

Investment Total investment is likely to be NOK 11.8 bn (2003 value). NOK 10.3 bn (2003 value) had been invested at 31.12.02.

Operating organisation Kristiansund

Main supply base Kristiansund

1 Petoro AS serves as the licensee for the SDFI.

Njord was proven in 1986 and lies in 330 metres of water about 30 km west of Draugen. Coming on stream in September 1997, the field has been developed with a steel-hulled semi-submersible production, drilling and quarters platform - Njord A. Subsea wells are tied back to this facility, with oil stored in a dedicated vessel - Njord B - located 2.5 km from the production platform. The crude is transferred via a flowline, with power supplied by cable from the platform. Oil is loaded into shuttle tankers for transport to the market. Njord B is remotely operated from the A platform except during discharging operations and maintenance campaigns.

122 FIELDS IN PRODUCTION Oil: 1 000 b/d

250 200 150 100 50 0 1997 1998 1999 2000 2001 2002 2003 12

Norne

Blocks and Block 6608/10 - production licence 128. Awarded 1986. production licences Block 6508/1 - production licence 128B. Awarded 1998.

Progress Government approval: March 1995 Production start-up: November 1997

Operator Statoil ASA

Licensees Petoro AS1 54.0% Statoil ASA 25.0% Norsk Hydro Produksjon a.s 8.1% Norsk Agip AS 6.9% Enterprise Oil Norge AS 6.0%

Recoverable reserves Originally present: Remaining at 31.12.02: 87.4 mill scm oil 40.4 mill scm oil 13.7 bn scm gas 11.8 bn scm gas 1.4 mill tonnes NGL 1.3 mill tonnes NGL

Production Estimated production in 2003: Oil: 164 000 b/d Gas: 0.9 bn scm NGL: 0.098 mill tonnes

Investment Total investment is likely to be NOK 19 bn (2003 value). NOK 15.1 bn (2003 value) had been invested at 31.12.02.

Operating organisation Harstad

Main supply base Sandnessjøen

1 Petoro AS serves as the licensee for the SDFI.

Norne lies in 380 metres of water, about 80 km north of Heidrun and roughly 200 km from the north Norwegian coast. The field has been developed with a production and storage ship tied to subsea templates. Flexible risers carry wellstreams to the vessel, which weathervanes around a cylindrical turret moored to the seabed. This ship carries processing facilities on its deck and storage tanks for oil. Pro- cessed crude can be transferred over the stern to tankers. A pipeline tied into the Åsgard Transport system has been laid for gas export.

FIELDS IN PRODUCTION 123 Oil: 1 000 b/d Gas: bn scm/year

160 12 140 10 120 100 8 80 6 60 4 40 20 2 0 0 12 1999 2000 2001 2002 2003

Åsgard

Blocks and Block 6407/2 - production licence 074. Awarded 1982. production licences Block 6407/3 - production licence 237. Awarded 1998. Block 6506/11 - production licence 134. Awarded 1987. Block 6506/12 - production licence 094. Awarded 1984. Block 6507/11 - production licence 062. Awarded 1981. Block 6406/3 - production licence 094B. Awarded 2002

Progress Government approval: June 1996 Production start-up: May 1999

Operator Statoil ASA

Licensees Petoro AS1 35.50% Statoil ASA 25.00% Norsk Hydro Produksjon a.s 9.60% Norsk Agip AS 7.90% TotalFinaElf Exploration Norge AS 7.65% Mobil Development Norway A/S 7.35% Fortum Petroleum AS 7.00%

Recoverable reserves Originally present: Remaining at 31.12.02: 67.9 mill scm oil 39.6 mill scm oil 191.9 bn scm gas 180.2 bn scm gas 32.9 mill tonnes NGL 31.4 mill tonnes NGL 47.1 mill scm condensate 43.3 mill scm condensate

Production Estimated production in 2003: Oil: 124 000 b/d Gas: 10.9 bn scm NGL: 1.75 mill tonnes Condensate: 4.88 mill scm

Investment Total investment is likely to be NOK 60.1 bn (2003 value). NOK 54.6 bn (2003 value) had been invested at 31.12.02.

Operating organisation Stjørdal

Main supply base Kristiansund

1 Petoro AS serves as the licensee for the SDFI.

124 FIELDS IN PRODUCTION 12

Åsgard comprises the Midgard, Smørbukk and Smørbukk South discoveries, made in 1981, 1984 and 1985 respectively. Water depths are in the 240-300 metre range.

The field has been developed with the Åsgard A production ship for oil and condensate, which came on stream in May 1999, and the Åsgard B floating gas platform. The latter began production in October 2000.

Rich gas is piped to Kårstø north of Stavanger for processing and fractionation of the liquid components, with the dry gas sent on to continental Europe through the Europipe II line.

FIELDS IN PRODUCTION 125 Fields which have ceased production The following fields had ceased to produce at 31 December 2001 Albuskjell Blocks 1/6 and 2/4 Development approved 1975 Cessation plan/ The cessation plan was approved by the authorities on decommissioning 21 December 2001 and in Report no 47 (1999-2000) to the Storting. Production start-up 1979 Production ceased 1998 Total production Oil: 7.4 mill scm Gas: 15.5 bn scm NGL: 1 mill tonnes over field lifetime

Cod Block 7/11 Development approved 1973 Cessation plan/ The cessation plan was approved by the authorities on decommissioning 21 December 2001 and in Report no 47 (1999-2000) to the Storting. Production start-up 1977 Production ceased 1998 Total production Oil: 2.9 mill scm Gas: 7.3 bn scm NGL: 0.5 mill tonnes over field lifetime

East Frigg Block 25/1 and 25/2 Development approved 1984 Cessation plan/ Storting proposition no 8 (1998-1999) and Report no 47 (1999-2000) decommissioning to the Storting. Production start-up 1988 Production ceased 1997 Total production Gas: 9.2 bn scm Condensate: 0.1 mill scm over field lifetime

Edda Block 2/7 Development approved 1975 Cessation plan/ The cessation plan was approved by the authorities on decommissioning 21 December 2001 and in Report no 47 (1999-2000) to the Storting. Production start-up 1979 Production ceased 1998 Total production Oil: 4.8 mill scm Gas: 2 bn scm NGL: 0.2 mill tonnes over field lifetime

126 FIELDS IN PRODUCTION Frøy Blocks 25/2 and 25/5 Development approved 1992 Cessation plan/ The cessation plan was approved by the authorities on 29 May 2001 decommissioning and Report no 47 (1999-2000) to the Storting. Production start-up 1995 Production ceased 2001 Total production Oil: 5.6 mill scm Gas: 1.6 bn scm Condensate: 0.1 mill tonnes over field lifetime

Lille-Frigg Block 25/2 Development approved 1991 Cessation plan/ Storting proposition no 53 (1999-2000) and Report no 47 (1999-2000) decommissioning to the Storting. Production start-up 1994 Production ceased 1999 Total production Gas: 2.2 bn scm Condensate: 1.3 mill scm over field lifetime

Mime Block 7/11 Development approved 1992 Cessation plan/ Storting proposition no 15 (1996-1997) and Report no 47 (1999-2000) decommissioning to the Storting. Production start-up 1990 Production ceased 1993 Total production Oil: 0.4 mill scm Gas: 0.1 bn scm over field lifetime

North-East Frigg Blocks 25/1 and 30/10 Development approved 1980 Cessation plan/ Storting proposition no 36 (1994-95) decommissioning Production start-up 1983 Production ceased 1993 Total production Gas: 11.6 bn scm NGL: 0.04 mill tonnes over field lifetime

FIELDS IN PRODUCTION 127 Odin Blocks 30/10 Development approved 1980 Cessation plan/ Storting proposition no 50 (1995-1996) and Report no 47 (1999-2000) decommissioning to the Storting. Production start-up 1984 Production ceased 1994 Total production Gas: 27.3 bn scm over field lifetime

Tommeliten Gamma Block 1/9 Development approved 1986 Cessation plan/ Storting proposition no 53 (1999-2000) and Report no 47 (1999-2000) decommissioning to the Storting. Production start-up 1988 Production ceased 1998 Total production Oil: 3.9 mill scm Gas: 9.7 bn scm NGL: 0.6 mill tonnes over field lifetime

West Ekofisk Block 2/4 Development approved 1973 Cessation plan/ The cessation plan was approved by the authorities on 21 December decommissioning 2001 and in Report no 47 (1999-2000) to the Storting. Production start-up 1977 Production ceased 1998 Total production Oil: 12.2 mill scm Gas: 26 bn scm NGL: 1.4 mill tonnes over field lifetime

Yme Block 9/1, 9/2 and 9/5 Development approved 1995 Cessation plan/ The cessation plan was approved by the authorities on 4 May 2001 decommissioning Production start-up 1996 Production ceased 2001 Total production Oil: 7.9 mill scm over field lifetime

128 FIELDS IN PRODUCTION 129